Laser dispersion spectroscopy for borehole analysis

ABSTRACT

This disclosure presents a process and system to determine characteristics of a subterranean formation proximate a borehole. Borehole material is typically pumped from the borehole, though borehole material can be used within the borehole as well. Extracted material of interest is collected from the borehole material and prepared for analyzation. Typically, the preparation can be a separation process, a filtering process, a moisture removal process, a pressure control process, a flow control process, a cleaning process, and other preparation processes. The prepared extracted material is placed in a laser dispersion spectroscopy device (LDS) where measurements can be taken. A LDS analyzer can generate results utilizing the measurements, where the results of the extracted material can include one or more of composition parameters, alkene parameters, and signature change parameters. The results can be communicated to other systems and processes to be used as inputs into well site operation plans and decisions.

TECHNICAL FIELD

This application is directed, in general, to utilizing a laserdispersion spectroscopy device with borehole material and, morespecifically, to determining subterranean formation characteristics.

BACKGROUND

In the hydrocarbon industry, parameters regarding a subterraneanformation surrounding a borehole is information that may be used asinputs to decisions and operation plans in furthering development of thewell site. The parameters of the subterranean formation can includefracture information, composition, permeability, porosity and othercharacteristics. The industry uses a variety of sensors to collectmeasurements that are then analyzed and used to generate thesubterranean formation parameters, such as seismic sensors,electromagnetic sensors, acoustic sensors, thermal sensors, chemicalsensors, and other sensor types. The data gained from these sensors mayvary as to quality and ease of obtaining the measurements. A method ofdetermining these characteristics with higher quality and accuracy wouldbe beneficial.

SUMMARY

In one aspect, a method is disclosed. In one embodiment the methodincludes (1) collecting extracted material from a location in asubterranean formation, wherein the location is proximate a position ofa hydrocarbon operation within a borehole, (2) preparing the extractedmaterial, wherein extraneous material is removed, (3) putting theextracted material into a laser dispersion spectroscopy (LDS) device,(4) initiating a LDS process utilizing the extracted material, and (5)generating results from an analyzation of the LDS process.

In another aspect, a system to analyze extracted material, extractedfrom a location within a borehole is disclosed. In one embodiment thesystem includes (1) an extracted material collector, capable ofcollecting the extracted material to be analyzed from borehole material,(2) an extracted material preparer, capable of receiving the extractedmaterial from the extracted material collector and capable of cleaning,separating, isolating, and altering the extracted material to preparethe extracted material for analysis, (3) a LDS device, capable ofreceiving the extracted material from the extracted material preparerand capable of performing a LDS process on the extracted material, and(4) a LDS analyzer, capable of producing results from an output of theLDS device.

In another aspect, a computer program product having a series ofoperating instructions stored on a non-transitory computer-readablemedium that directs a data processing apparatus when executed thereby toperform operations to analyze extracted material is disclosed. In oneembodiment, the operations include (1) directing a collecting of theextracted material from a location in a subterranean formation, whereinthe location is proximate a position of hydrocarbon operations within aborehole, (2) instructing a preparing of the extracted material, whereinextraneous material is removed, (3) initiating a putting of theextracted material into a LDS device, (4) executing a LDS processutilizing the extracted material, (5) analyzing results from the LDSprocess, and (6) communicating the results to one or more other systems.

BRIEF DESCRIPTION

Reference is now made to the following descriptions taken in conjunctionwith the accompanying drawings, in which:

FIG. 1 is an illustration of a diagram of an example well system;

FIG. 2 is an illustration of a diagram of an example hydraulicfracturing well system;

FIG. 3 is an illustration of a diagram of an example offshore wellsystem;

FIG. 4A is an illustration of a block diagram of an example laserdispersion spectroscopy (LDS) analyzation system located at a surface ofa well site;

FIG. 4B is an illustration of a diagram of an example LDS analyzationsystem located at a downhole location within a borehole;

FIG. 5A is an illustration of a flow diagram of an example methodutilizing a LDS system at a well site;

FIG. 5B is an illustration of a flow diagram of an example method,building on FIG. 5A, to perform decision checkpoints; and

FIG. 6 is an illustration of a block diagram of an example LDS system.

DETAILED DESCRIPTION

In the hydrocarbon production industry, users, such as well operators orengineers, can use information regarding the subterranean formationaround a borehole to make further adjustments to the well siteoperations. In a drilling operation, such as for a production well,intercept well, relief well, and other well types, being able todetermine the composition of the surrounding subterranean formation canbe useful as inputs into a well site operation plan. In casingoperations, the placement of casing, the thickness used, and othercasing factors can be determined by the characteristics of thesurrounding subterranean formation.

Sampling cuttings from drilling operations may not reveal the naturalcharacteristics of the subterranean formation as drilling operations cancause a change in the sampled cuttings due to action of the drill bit.Corrections to the altered characteristics are needed to more accuratelydetermine the characteristics of the subterranean formation. Using acomparison of a sampled core, sidewall core, or subterranean formationimage to the collected cuttings, corrections can be made to thedetermined composition characteristics and the effects of the drill biton the composition can be compensated. In some aspects, formation planeorientation can be determined from the cuttings.

Other subterranean formation characteristics can include a determinationof the composition of the subterranean formation and whether it containsorganic or inorganic material. In some aspects, during drillingoperations, an unsaturated hydrocarbon change or a signature change canbe detected and an alert sent to the users indicating the changedcondition downhole. A signature change, e.g., a phase or compositionsignature change, can be, for example, a gas/liquid transition, or theincrease or decrease of water in the borehole.

In the industry today, there are several methods utilized to obtain thevarious subterranean formation characteristics, such as seismic sensors,electromagnetic sensors, thermal sensors, chemical sensors, acousticsensors, radiation sensors, and other sensor types. In some aspects,visual inspection of cuttings can be used. The ability to take sensorreadings downhole can vary as to effectiveness, such as some sensorsoperate while the drilling operations cease. Other restrictions relateto the power needed by the sensors and the data rates needed to sendcollected measurements to a surface system.

This disclosure presents a laser dispersion spectroscopy (LDS) systemthat can determine several subterranean formation characteristics. Thedisclosed system can be performed at a surface location proximate thewell site where power consumption of the sensors and data transmissionrates can be maintained at appropriate levels. The disclosed system canbe performed at regular time intervals, where the time interval can benearly continuous or at a specified time interval. In some aspects, theLDS system can be performed downhole, where the LDS device is locatedproximate downhole tools, such as power supplies, transceivers, andother equipment, such as drill bits.

Cuttings can be collected from the subterranean formation, such asextracted from the drilling mud, hydraulic fracturing fluid, chemicalfracturing fluid, and other fluids located in the borehole or pumped toa surface location. The cuttings can be prepared, such as cleaned,drained of fluid, filtered, separated, and otherwise processed forfurther analysis, such as removing extraneous material.

In some aspects, the LDS device can utilize multiple generated energywave lengths to determine composition of the extracted material bydetecting the energy wave dispersion, such as a mineral composition, amolecular composition, or an organic composition. The increasedsensitivity and selectivity with broad linearity can improve uponresults produced by current gas chromatography and liquid phasedetectors. In some aspects, the disclosed processes can be applied forgas phase analysis (utilizing a photoacoustic spectroscopy gas phasedevice), liquid phase analysis (utilizing a photoacoustic spectroscopyliquid phase device), solid phase analysis (utilizing a photoacousticspectroscopy solid phase device), and isotropic analysis (utilizing aphotoacoustic spectroscopy isotropic device) in the gas phase. Theenergy waves can be for example, sound waves, infrared waves, visiblelight waves, gamma waves, x-rays, and other energy wave lengths.

In some aspects, the LDS device can be utilized in conjunction withselective physical-chemical separation techniques (utilizing aphysical-chemical separation device), such as isotropic testing systems.In some aspects, the LDS device can be utilized in combination with agas chromatography (GC) system, such as a GC combustion system or othertypes of GC systems. The GC system can be part of the LDS device, aseparate device included with the LDS device, or a separate deviceproximate the LDS device. In some aspects, the LDS device can beutilized in combination with a liquid chromatography (LC) system, suchas a LC combustion system or other types of LC systems. The LC systemcan be part of the LDS device, a separate device included with the LDSdevice, or a separate device proximate the LDS device.

Turning now to the figures, FIG. 1 is an illustration of a diagram of anexample well system 100 using a LDS device for analyzing cuttingsextracted from a downhole location where a hydrocarbon operation isbeing conducted, for example, a drilling system, a logging whiledrilling (LWD) system, a measuring while drilling (MWD) system, aseismic while drilling (SWD) system, a telemetry while drilling system,an extraction system, a formation evaluation system, a fluids evaluationsystem, a production system, a wireline system with a pump, and otherhydrocarbon well systems such as relief wells and intercept wells. Wellsystem 100 includes a derrick 105, a well site controller 107, and acomputing system 108. Well site controller 107 includes a processor anda memory and is configured to direct operation of well system 100.Derrick 105 is located at a surface 106.

Extending below derrick 105 is a borehole 110 with downhole tools 120 atthe end of a drill string. Downhole tools 120 can include variousdownhole tools and bottom hole assemblies (BHA), such as drilling bit122. Other components of downhole tools 120 can be present, such as alocal power supply (e.g., generators, batteries, or capacitors),telemetry systems, sensors, transceivers, and control systems. Borehole110 is surrounded by subterranean formation 150.

The drilling mud pumped out of borehole 110 can be stored in a mudstorage 130. Extracted material from mud storage 130 can be collectedand moved to a extracted material preparer 140. The extracted materialcan be cleaned, separated, have fluid drained, and other preparationfunctions, such as pulverizing solids or converting gases to carbondioxide. After preparation, the extracted material can be moved to a LDSdevice 145 where a LDS process can be performed on the extractedmaterial. Results can be generated by LDS device 145 or by anothersystem, such as well site controller 107 or computing system 108. LDSdevice 145 can be one or more devices. For example. a separate LDSdevice can be utilized for the phase state of the extracted material,such as a gas phase device, a liquid phase device, a solid phase device,and an isotropic device.

Well site controller 107 or computing system 108 which can becommunicatively coupled to well site controller 107, can be utilized tocommunicate with downhole tools 120, such as sending and receivingtelemetry, data, instructions, and other information. Computing system108 can be proximate well site controller 107 or be a distance away,such as in a cloud environment, a data center, a lab, or a corporateoffice. Computing system 108 can be a laptop, smartphone, PDA, server,desktop computer, cloud computing system, other computing systems, or acombination thereof, that are operable to perform the process andmethods described herein. Well site operators, engineers, and otherpersonnel can send and receive data, instructions, measurements, andother information by various conventional means with computing system108 or well site controller 107.

Well site controller 107 or computing system 108 can also communicatewith extracted material preparer 140 and LDS device 145 to directoperations and receive the measured data and results. For example, LDSdevice 145 can perform an analysis on extracted material and transmitthe results to well site controller 107 or computing system 108. In analternative aspect, the measurements taken by LDS device 145 can becommunicated to well site controller 107 or computing system 108 and theresults generated in one or more of those respective systems.

In FIG. 1 , the extracted material preparer 140 and LDS device 145 isrepresented at a surface location proximate derrick 105. In otheraspects, extracted material preparer 140 and LDS device 145 can belocated downhole as part of downhole tools 120. In this aspect, themeasurements taken or the generated results can be communicated upholeto well site controller 107 or computing system 108. A user or well sitecontroller 107 can utilize the generated results to direct furtheroperations of the well system 100, such as adjusting drillingoperations, fluid flow, rate, and composition, and adjusting a well siteoperation plan.

FIG. 2 is an illustration of a diagram of an example hydraulicfracturing (HF) well system 200 undergoing a hydrocarbon operation. HFwell system 200 demonstrates a nearly horizontal borehole undergoing ahydraulic fracturing operation. In other aspects, HF well system 200 canbe other types of HF well systems or chemical fracturing operation wellsystems.

HF well system 200 includes surface well equipment 205 located at asurface 206, well site control equipment 207, and a computing system208. In some aspects, well site control equipment 207 is communicativelyconnected to separate computing system 208, for example, a server, datacenter, cloud service, tablet, laptop, smartphone, or other types ofcomputing systems. Computing system 208 can be located proximate to wellsite control equipment 207 or located a distance from well site controlequipment 207, and can be utilized by a well system engineer andoperator to transceive data, instructions, and other information with anextracted material preparer 260 and a LDS device 265. A hydraulic fluidreservoir 250 can store fluid pumped out of borehole 210. Extractedmaterial contained in the hydraulic fluid can be collected and moved toextracted material preparer 260 where the extracted material can becleaned, drained, separated, or otherwise prepared, such as describedfor extracted material preparer 140.

Extending below surface 206 from surface well equipment 205 is aborehole 210. Borehole 210 can have zero or more cased sections and abottom section that is cased or uncased. Inserted into borehole 210 is afluid pipe 220. The bottom portion of fluid pipe 220 has the capabilityof releasing downhole material 230, such as carrier fluid with divertermaterial, from fluid pipe 220 to subterranean formations 235 containingfractures 240. The release of downhole material 230 can be by slidingsleeves, valves, perforations in fluid pipe 220, or by other releasemeans. At the end of fluid pipe 220 is an end of pipe assembly 225,which can include one or more downhole tools 227 or an end cap assembly.

LDS device 265 can communicate measurements or analyzed results to wellsite control equipment 207 or computing system 208. Extracted materialpreparer 260 and LDS device 265, which can be one or more of the LDSdevices as described for LDS device 145, can receive inputs from a user,well site control equipment 207, or computing system 208. The inputs candirect operations, such as specifying a time interval to perform theanalyzation, a verification time interval, or a calibration timeinterval. In some aspects, the inputs can include referencecalibrations, locations within the borehole to perform the LDS analysis,core sample data (such as collected by downhole tools 227), and otherinputs to direct operations such as specifying the utilization of analgorithm or a machine learning process. In some aspects, extractedmaterial preparer 260 and LDS device 265 can be located with downholetools 227.

FIG. 3 is an illustration of a diagram of an example offshore wellsystem 300, where an electric submersible pump (ESP) assembly 320 isplaced downhole in a borehole 310 below a body of water 340, such as anocean or sea. Borehole 310, protected by casing, screens, or otherstructures, is surrounded by subterranean formation 345. ESP assembly320 can also be used for onshore operations. ESP assembly 320 includes awell controller 307 (for example, to act as a speed and communicationscontroller of ESP assembly 320), an ESP motor 314, and an ESP pump 324.

Well controller 307 is placed in a cabinet 306 inside a control room 304on an offshore platform 305, such as an oil rig, above water surface344. Well controller 307 is configured to adjust the operations of ESPmotor 314 to improve well productivity. In the illustrated aspect, ESPmotor 314 is a two-pole, three-phase squirrel cage induction motor thatoperates to turn ESP pump 324. ESP motor 314 is located near the bottomof ESP assembly 320, just above downhole sensors within borehole 310. Apower/communication cable 330 extends from well controller 307 to ESPmotor 314.

In some aspects, ESP pump 324 can be a horizontal surface pump, aprogressive cavity pump, a subsurface compressor system, or an electricsubmersible progressive cavity pump. A motor seal section and intakesection may extend between ESP motor 314 and ESP pump 324. A riser 315separates ESP assembly 320 from water 340 until sub-surface 342 isencountered, and a casing 316 can separate borehole 310 fromsubterranean formation 345 at and below sub-surface 342. Perforations incasing 316 can allow the fluid of interest from subterranean formation345 to enter borehole 310.

Offshore well system 300 is demonstrating an example where an extractedmaterial preparer 360 and LDS device 365 are located downhole as part ofESP assembly 320. As cuttings, through mud or fluid, is pumped up to thesurface, the LDS borehole analyzer system can collect the cuttings andfluid and process them as described in well system 100 and HF wellsystem 200. The measurements taken and the analyzed results can becommunicated to well controller 307. In other aspects, extractedmaterial preparer 360 and LDS device 365 can be located on offshoreplatform 305.

FIGS. 1 and 2 depict onshore operations. Those skilled in the art willunderstand that the disclosure is equally well suited for use inoffshore operations. FIGS. 1, 2, and 3 depict specific boreholeconfigurations, those skilled in the art will understand that thedisclosure is equally well suited for use in boreholes having otherorientations including vertical boreholes, horizontal boreholes, slantedboreholes, multilateral boreholes, and other borehole types.

FIG. 4A is an illustration of a block diagram of an example LDSanalyzation system 400 located at a surface of a well site. LDSanalyzation system 400 can be used to analyze material extracted from adown hole location, such as from mud, hydraulic fracturing fluid,chemical fracturing fluid, and other fluids and materials pumped to thesurface of the well site. A well system 410 can pump one or more fluidsand materials from a downhole location as indicated along directionalflow arrow 412. The fluid and materials can be pumped to a storage area415.

The extracted material of interest can be extracted from storage area415, such as using an extracted material collector 420. The extractedmaterial can be in any phase state, such as a gas, liquid, or solid. Theextraction process can vary for each type of phase state to minimize aloss of material during the extraction process. In this example,extracted material collector 420 is further capable of preparing theextracted material. In some aspects, the collection and preparationfunctions can be separated into different devices, as indicted by thedotted line dividing extracted material collector 420.

For the preparation function, the extracted material can be prepareddepending on the phase state. For example, a gas can be separated fromthe material that traps the gas and separated from other gasses trappedin the material. The preparation can be a separation process, afiltering process, a dilution process, a moisture removal process, apressure control process, a flow control process, a flow rate adjustmentprocess, a cleaning process, an isolating process, a removing extraneousmaterial process, an additional support gases process, and otherpreparation processes. In some aspects, the gas can be converted tocarbon dioxide, such as through a combustion process. A liquid can beseparated from other material in the collected material, and similar tothe gas state, can be filtered, have its pressure adjusted, have itsflow adjusted, have additional fluids added, and other preparationsteps. A solid, in addition to the preparation steps described for theother phase states, can be cleaned, drained of fluid, pulverized, andhave other preparation steps. In some aspects, organic extractedmaterial can be prepared differently than inorganic extracted material.

Extracted material collector 420 can be one or more devices, such as aseparate device to handle each of the phase states or type of extractedmaterial. The prepared extracted material can then be moved to a LDSdevice 425. In some aspects LDS device 425 can include LDS analyzer andin other aspects, LDS analyzer can be a separate device or computingsystem, as shown by the dotted line in LDS device 425. There can be morethan one LDS device 425 to analyze different types of extracted materialor to perform different types of analysis. In some aspects, LDS device425 can include one or more of a GC system, a GC combustion system, a LCsystem, or a LC combustion system. In some aspects, LDS device 425 caninclude other types of physical-chemical separation techniques.

The measurements collected by LDS device 425 can then be analyzed by aLDS analyzer that is part of LDS device 425 or is performed by aseparate computing system. In some aspects, the separate computingsystem can be a well site controller, such as well site controller 430,a computing system, such as computing system 432, or other computingsystems.

The LDS analyzer can perform one or more operations to produce a resultthat can be further communicated to other systems or users. For example,the results can be transmitted, using a results transmitter, to wellsite controller 430, computing system 432, a user 434, or a data center436 which can be a cloud environment. In some aspects, the results canbe transmitted to a downhole tool controller, a well site operation plansystem, or other computing system. The well site controller or well siteoperation plan can utilize the results to determine next steps, or toadjust plans or operations. LDS analyzation system 400 is shown as ademonstration of a functional implementation. Extracted materialcollector 420 and LDS device 425 can be implemented using one or moredevices to handle the described functions of each device.

The results that are produced can vary with the type of analysis beingperformed and the type of extracted material being analyzed. In someaspects, a spectral deconvolution process can be performed based onreference standards or can utilize an artificial intelligence processsuch as machine learning algorithms or deep neural networks. Thespectral deconvolution process can determine the composition of theextracted material. In some aspects, the spectral deconvolution processcan determine if the extracted material is organic or inorganic.

In some aspects, such as when the extracted material is a solid, avitrinite reflectance can be performed for organic composition analysisto generate a result including a vitrinite reflectance parameter. Insome aspects, an isotropic analysis can be performed on the extractedmaterial, for example, to determine the amount of methane containingvarious particles that is detected. In gas phase analysis or isotropicanalysis, the target gas or target liquid released from the extractedmaterial can be analyzed at low levels of concentration to determine themeasurements. In some aspects, the results can include a status of thesystem.

In some aspects, the analysis can determine if unsaturated linearhydrocarbon, e.g., alkenes, compositions are present. An alert, e.g., anunsaturated hydrocarbon message, can be output when a target quantity ofunsaturated hydrocarbons is met or exceeded. This can be an indicator ofinefficient drilling and therefore can be used as an input to adjustdrilling operations.

In some aspects, a phase signature or composition signature can changeover time for subsequent samples of extracted material. For example, theprocess can detect a drop in oil and an increase in water in theextracted material, or a gas can now be detected as occurring in aliquid state. Once the phase or composition signature is ascertained forthe extracted material, the signature can be compared to one or morepreviously collected samples of extracted material. When the signaturechange meets or exceeds a specified signature change parameter, then asignature change message can be output indicating the change. Forexample, the signature change parameter can indicate that an oil-waterratio should change by at least a specified percentage before asignature change message is communicated. The signature change messagecan be used as an input to direct further operations of the well site.

In some aspects, if a selected reference peak shifts or if a specifiedverification time interval has elapsed, the LDS analyzer can direct LDSdevice 425 to perform a calibration verification, for example, using acalibration gas or liquid, e.g., a known sample. In some aspects, if theverification of calibration fails or if a specified calibration timeinterval elapses, LDS device 425 can perform a calibration process. Acalibration parameter can be included in the communicated results.

FIG. 4B is an illustration of a diagram of an example LDS analyzationsystem 450 located at a downhole location within a borehole 456.Borehole 456 is located in a subterranean formation 455. Subterraneanformation 455 can be heterogeneous or homogeneous formation types.Borehole 456 can be borehole 110 of FIG. 1 .

Inserted into borehole 456 is a drill string 460. Attached to drillstring 460 is an optional powered isolation sub 462. Powered isolationsub 462 can electrically isolate the lower portion of drill string 460,and can pass through to the lower attached BHA a portion of theelectrical power transmitted through drill string 460. A traditionalisolation sub 464 can be located lower on drill string 460 compared topowered isolation sub 462. Traditional isolation sub 464 can provideelectrical isolation for the lower attached components. A extractedmaterial collector/preparer 472 and a LDS device/analyzer 474 can belocated below traditional isolation sub 464. At the end of drill string460 is a drill bit 480. Other tools, devices, power supplies, andtransceivers can be located on, in, or around drill string 460.

Similar to LDS analyzation system 400, extracted materialcollector/preparer 472 and LDS device/analyzer 474 can perform thedescribed functions. In this example, the extracted material collectorand the extracted material preparer are shown as a single extractedmaterial collector/preparer 472. In some aspects, they can be separatedevices, as indicated by the dashed line. The LDS device and the LDSanalyzer are shown as a single LDS device/analyzer 474. In some aspects,they can be separate devices, as indicated by the dashed line. In someaspects, the LDS analyzer functions can be performed by other systems,such as surface equipment, e.g., a well site controller or computingsystem. In some aspects, LDS device/analyzer 474 can include one or moreof a GC system, a GC combustion system, a LC system, or a LC combustionsystem. In some aspects, LDS device/analyzer 474 can include other typesof physical-chemical separation techniques.

Instructions and input parameters can be provided by downholecommunication 490. Measurements and results can be provided by an upholecommunication 492, such as results generated from LDS device/analyzer474 and a status of the system. Downhole communication 490 and upholecommunication 492 can be performed by conventional means.

FIG. 5A is an illustration of a flow diagram of an example method 501utilizing a LDS system at a well site. Method 501 can be used to analyzeextracted material collected from drilling mud or other fluids pumped upfrom a borehole. The analysis can be used as inputs into other decisionmaking processes and systems. Method 501 starts at a step 510 andproceeds to a step 520. In the step 520, extracted material can becollected from drilling mud, hydraulic fracturing fluid, chemicalfracturing fluid, and other fluids pumped from a borehole. Thecollection process can vary as different types of extracted material canbe handled by separate processes, such as gas extracted materialcollection being handled differently than solid extracted materialcollection. In some aspects, the extracted material can be collected ata downhole location where the fluid is not first pumped to a surfacelocation.

Proceeding to a step 530, the extracted material can be prepared. Thepreparations can be zero or more of separating, draining fluid,cleaning, isolating, adding support material, diluting, filtering,changing to a different phase state or form, combusting, removingmoisture, changing pressure, changing flow rate, and other preparationprocesses. Different types of extracted material can utilize varyingpreparation techniques, for example, solids can utilize a pulverizingprocess or variable dilution materials can be utilized.

In a step 540, the prepared extracted material can be moved into a LDSdevice. There can be more than one LDS device, such as separate devicesto conduct analysis of different extracted material phase states,allowing multiple analyses to be generated.

Proceeding to a step 550, the LDS process can be initiated and themeasurements collected. The measurements can relate to the compositionof the extracted material. In a step 560, the collected measurements canbe analyzed to determine one or more characteristics of the extractedmaterial, i.e., results. The results can be communicated to othersystems and processes, to users, and be used as inputs to well siteoperation plans, and other decision processes. Method 501 ends at a step595.

FIG. 5B is an illustration of a flow diagram of an example method 502,building on FIG. 5A, to perform decision checkpoints. Steps that aresimilar in method 501 and method 502 are shown using dashed outlines,and steps that are new are shown using solid outlines. Method 502 startsat step 510 and proceeds to a step 512. In step 512, the process canreceive one or more inputs. The inputs can be parameters for how toproceed in other steps. The inputs can include a signature changeparameter for phase signatures, a signature change parameter forcomposition signatures, reference peak parameters, e.g., a referencestandard parameter, for one or more types of extracted material, acalibration sample parameter indicating the type of calibration toperform, a verification time interval, a calibration time interval, amachine learning algorithm parameter specifying an algorithm to utilize,target unsaturated hydrocarbon parameter, distance parameters betweenextracted material samples, distance parameters to indicate a length toextrapolate a core sample, parameters regarding the drill bit and fluidsutilized downhole, and other input parameters.

Proceeding to step 520, method 502 proceeds through to step 530, step540, step 550, and step 560. Step 560 can further include a step 564which can utilize machine learning algorithms, artificial intelligence,and other intelligent systems to extrapolate results generated by theLDS analyzer to generate results that are better suited to the needs ofthe receivers of the information, such as a user or a well sitecontroller. Step 560 can further include a step 566 to verify thecalibration of the LDS device. The verification process can be initiatedif an elapsed time is exceeded, such as indicated by the verificationtime interval. The verification process can compare the results from theextracted material to a reference peak and if the extracted material hasa shifted peak by at least the reference peak parameter, a calibrationprocess can be requested.

Proceeding from step 566 is a decision step 570 to determine if thecalibration verification failed, or if an elapsed time from the lastcalibration has exceeded the calibration time interval. If the resultantis “Yes”, then method 502 proceeds to a step 574 where a calibrationprocess can be performed using a reference sample. If the resultant is“No”, then method 502 proceeds to a decision step 576.

In decision step 576, the process can determine the distance that thewell site operations have covered since the previous collection ofextracted material as compared to a distance parameter. The distanceparameter can be increased proportionately to an extrapolation length ofa core sample, such that an extended core sample can be used over agreater distance. For example, the drill bit can move a specified numberof inches or feet, or casing can be applied for specified number offeet, e.g., the distance between collecting extracted material. If theresultant of the comparison is that the distance parameter has been metor exceed, i.e., “Yes”, method 502 proceeds to step 520 where newextracted material is collected. If the resultant is “No”, method 502can remain at this step until the appropriate distance is covered oruntil another end state is reached. If an end state is reached, method502 ends at step 595.

Proceeding from step 560, in a step 580, the results can becommunicated, e.g., output, to users, other systems, or other processes.The outputs can be used as inputs to decision processes for the wellsite. Part of the results outputted by step 580 can include informationfor two additional decisions steps. In a decision step 584, thesignature of extracted material can be compared to a signature generatedfrom a previous iteration, e.g., previous execution, of method 502. Insome aspects, the signature can be a phase signature change, forexample, a gas turning to a liquid. In some aspects, the signature canbe a composition signature change, for example, a change in a ratio ofoil to water. The signature change amounts, e.g., the amount of changeto derive a “Yes” resultant, can be provided as inputs to the process,such as in step 512. For example, an oil-water ratio can be targeted atleast a twenty percent change, or other values can be utilized.

If a “Yes” resultant is determined, then method 502 proceeds to a step588 where a signature change message can be communicated to a user orsystem. This can be an alert that a change in downhole conditions can bebrought to the attention of a system or user, such as indicating achange in downhole operations. From step 588, method 502 can return tostep 580 and follow other paths forward. In decision step 584, a “No”resultant can proceed back to step 580 and proceeds along the otherpaths from step 580.

In a decision step 586, the detected quantity of unsaturatedhydrocarbons, i.e., unsaturated linear hydrocarbons, can be compared toa target unsaturated hydrocarbon parameter, such as received by step512. If the unsaturated hydrocarbon target is met or exceeded, then theresultant is “Yes” and method 502 proceeds to step 588 where aunsaturated hydrocarbon message can be communicated to a user or system.This can be an alert that a change in downhole conditions can be broughtto the attention of a system or a user, and can indicate a change indownhole operations. In decision step 586, a “No” resultant proceedsback to step 580 and proceeds along the other paths from step 580.

The order of steps presented in method 502 is for demonstrationpurposes. Several steps, such as step 566, step 580, decision step 570,decision step 584, and decision step 586 can be performed in variousorders and dependencies between them can be included or extended.

FIG. 6 is an illustration of a block diagram of an example LDS analyzersystem 600, which can be implemented as one or more devices. LDSanalyzer system 600 can be utilized to analyze extracted material from aborehole to determine composition parameters, unsaturated hydrocarbonparameters, signature change parameters, and other parameters. LDSanalyzer system 600 includes an extracted material collector 620, anextracted material preparer 630, a LDS device 640, and a LDS analyzer650.

LDS analyzer system 600 can receive inputs to direct operations, such astime intervals, target parameters, core samples, calibration references,borehole locations, and distances, selected algorithms to utilize, andother input parameters. The inputs can be received utilizing aconventional transceiver using conventional protocols, e.g., utilizing adata receiver. The received inputs can be received from a data source,such as a database, data file, user input, a well site controller, areservoir controller, or other data sources.

LDS analyzer system 600 can receive extracted material from boreholematerial, such as drilling mud, fluids, and other material pumped from aborehole. The borehole material can include cuttings and other materialfrom downhole of a borehole. Extracted material collector 620 cancollect extracted material of interest from the borehole material. Theextracted material can be prepared by extracted material preparer 630.The preparation can perform various operations depending on the analysisto be conducted and the type of extracted material to be analyzed.Preparation can include cleaning, filtering, separating, isolating,draining fluid, adding material, altering material, and otherpreparation functions.

The extracted material can be moved into a LDS device 640. LDS device640 can collect measurements on the extracted material, such ascomposition or densities. The measurements can be provided to LDSanalyzer 650 to analyze the measurements and generate results. LDSanalyzer 650 can be implemented as an application, a code library,dynamic link library, function, module, other software implementation,or combinations thereof. In some aspects, LDS analyzer 650 can beimplemented in hardware, such as a ROM, a graphics processing unit, orother hardware implementation. In some aspects, LDS analyzer 650 can beimplemented partially as a software application and partially as ahardware implementation.

LDS analyzer system 600 can communicate, using a results transmitter,one or more results to another system, such as to a user, a well sitecontroller, a computing system, a downhole tool controller, a well siteoperation plan system, or other well related system. The well sitecontroller, downhole tool controller, or well site operation plan systemcan utilize the results to determine future steps or operations, or toadjust plans. The receiving computing system can be included in thecomputing system where LDS analyzer 650 is executing or be located inanother computing system proximate or distance from LDS analyzer system600. LDS analyzer system 600 can be, or can include, conventionalinterfaces configured for transmitting and receiving data.

In some aspects, LDS analyzer system 600 can operate partially or fullyin serial or parallel mode such that analysis can be conducted on morethan one extracted material set at a time, allowing the overallprocessing time to be reduced. A memory or data storage of LDS analyzersystem 600 can be configured to store the processes and algorithms fordirecting the operation of LDS analyzer system 600.

A portion of the above-described apparatus, systems, or methods may beembodied in or performed by various analog or digital data processors,wherein the processors are programmed or store executable programs ofsequences of software instructions to perform one or more of the stepsof the methods. A processor may be, for example, a programmable logicdevice such as a programmable array logic (PAL), a generic array logic(GAL), a field programmable gate arrays (FPGA), or another type ofcomputer processing device (CPD). The software instructions of suchprograms may represent algorithms and be encoded in machine-executableform on non-transitory digital data storage media, e.g., magnetic oroptical disks, random-access memory (RAM), magnetic hard disks, flashmemories, and/or read-only memory (ROM), to enable various types ofdigital data processors or computers to perform one, multiple or all ofthe steps of one or more of the above-described methods, or functions,systems or apparatuses described herein.

Portions of disclosed examples or embodiments may relate to computerstorage products with a non-transitory computer-readable medium thathave program code thereon for performing various computer-implementedoperations that embody a part of an apparatus, device or carry out thesteps of a method set forth herein. Non-transitory used herein refers toall computer-readable media except for transitory, propagating signals.Examples of non-transitory computer-readable media include, but are notlimited to: magnetic media such as hard disks, floppy disks, andmagnetic tape; optical media such as CD-ROM disks; magneto-optical mediasuch as floppy disks; and hardware devices that are specially configuredto store and execute program code, such as ROM and RAM devices. Examplesof program code include both machine code, such as produced by acompiler, and files containing higher level code that may be executed bythe computer using an interpreter.

In interpreting the disclosure, all terms should be interpreted in thebroadest possible manner consistent with the context. In particular, theterms “comprises” and “comprising” should be interpreted as referring toelements, components, or steps in a non-exclusive manner, indicatingthat the referenced elements, components, or steps may be present, orutilized, or combined with other elements, components, or steps that arenot expressly referenced.

Those skilled in the art to which this application relates willappreciate that other and further additions, deletions, substitutions,and modifications may be made to the described embodiments. It is alsoto be understood that the terminology used herein is for the purpose ofdescribing particular embodiments only, and is not intended to belimiting, because the scope of the present disclosure will be limitedonly by the claims. Unless defined otherwise, all technical andscientific terms used herein have the same meaning as commonlyunderstood by one of ordinary skill in the art to which this disclosurebelongs. Although any methods and materials similar or equivalent tothose described herein can also be used in the practice or testing ofthe present disclosure, a limited number of the exemplary methods andmaterials are described herein.

What is claimed is:
 1. A method, comprising: collecting extractedmaterial from a location in a subterranean formation, wherein thelocation is proximate a position of hydrocarbon operations within aborehole; preparing the extracted material, wherein extraneous materialis removed; putting the extracted material into a laser dispersionspectroscopy (LDS) device; initiating a LDS process utilizing theextracted material; and generating results from analyzation of the LDSprocess, wherein the LDS process utilizes at least one of a gas phaseanalysis, a liquid phase analysis, or an isotropic analysis, and theextracted material is within pores of downhole material retrieved fromthe location.
 2. The method as recited in claim 1, further comprising:outputting the results to one or more of a well site controller, wellsite operation plan system, or a well site operator.
 3. The method asrecited in claim 1, wherein the hydrocarbon operation includes at leastone of a hydraulic fracturing operation, a chemical fracturingoperation, a casing operation, a drilling system, a logging whiledrilling system, a measuring while drilling system, and seismic whiledrilling system.
 4. The method as recited in claim 1, further comprisingrepeating the method at a distance parameter, wherein the distanceparameter is an input parameter.
 5. The method as recited in claim 1,wherein the LDS process further utilizes a solid phase analysis.
 6. Themethod as recited in claim 5, wherein for the solid phase analysis, thepreparing further comprises one or more of pulverizing the extractedmaterial, cleaning the extracted material, and draining fluid from theextracted material.
 7. The method as recited in claim 1, furthercomprising: determining a composition of the extracted materialutilizing a spectral deconvolution process using a reference standard ora machine learning algorithm, and outputting the composition as theresults.
 8. The method as recited in claim 7, wherein the resultsinclude at least one of a mineral composition, an organic composition,or a vitrinite reflectance parameter.
 9. The method as recited in claim1, further comprising: comparing a detected quantity of unsaturatedlinear hydrocarbons and a target quantity of unsaturated hydrocarbons,and outputting an unsaturated hydrocarbon message when the targetquantity of unsaturated hydrocarbons is exceeded.
 10. The method asrecited in claim 1, further comprising: ascertaining a phase signatureor a composition signature of the extracted material and outputting asignature change message when the respective of the phase signature orof the composition signature changes, utilizing a signature changeparameter, from a previous execution of the method.
 11. The method asrecited in claim 1, further comprising: verifying calibration of the LDSdevice when a selected reference peak shifts or at an end of a specifiedverification time interval; and calibrating the LDS device when theverifying calibration fails or after a specified calibration timeinterval.
 12. The method as recited in claim 1, wherein the LDS processutilizes at least one of a gas phase analysis or an isotropic analysisutilizing a target gas released from the extracted material, or a liquidphase analysis utilizing a target liquid released from the extractedmaterial.
 13. The method as recited in claim 12, further comprising:prepping the extracted material utilizing one or more of a filteringprocess, a moisture removal process, a separation process, a pressurecontrol process, a flow control process, or an additional support gasesprocess.
 14. The method as recited in claim 12, further comprising:converting respective of the target gas or the target liquid to carbondioxide.
 15. The method as recited in claim 12, further comprising:diluting respective of the target gas or the target liquid utilizing avariable dilution material.
 16. A system to analyze extracted material,extracted from a location within a borehole, comprising: an extractedmaterial collector, capable of collecting the extracted material to beanalyzed from borehole material; an extracted material preparer, capableof receiving the extracted material from the extracted materialcollector and capable of cleaning, separating, isolating, and alteringthe extracted material to prepare the extracted material for analysis; alaser dispersion spectroscopy (LDS) device, capable of receiving theextracted material from the extracted material preparer and capable ofperforming a LDS process on the extracted material; and a LDS analyzer,capable of producing results from an output of the LDS device, whereinthe LDS process utilizes at least one of a gas phase analysis, a liquidphase analysis, or an isotropic analysis, and the extracted material iswithin pores of downhole material retrieved from the location.
 17. Thesystem as recited in claim 16, wherein the system is located downholeproximate to a hydrocarbon operation.
 18. The system as recited in claim16, wherein the extracted material collector collects the extractedmaterial from drilling mud, hydraulic fracturing fluid, or chemicalfracturing fluid.
 19. The system as recited in claim 16, wherein theextracted material preparer is further capable of converting gas tocarbon dioxide, pulverizing the extracted material that is a solid,diluting the extracted material, and draining fluid from the extractedmaterial.
 20. The system as recited in claim 16, wherein the LDS deviceis one of a LDS gas phase device, a LDS liquid phase device, a LDS solidphase device, or a LDS isotropic device.
 21. The system as recited inclaim 16, wherein the results from the LDS analyzer comprise one or moreof a mineral composition, an organic composition, a molecularcomposition, a calibration parameter of the LDS device, or a status ofthe system.
 22. The system as recited in claim 16, further comprising: adata receiver, capable of receiving inputs, wherein the inputs are oneor more of a verification time interval, a calibration time interval, areference peak parameter for one or more types of extracted material,the location within the borehole, a reference standard parameter, amachine learning algorithm parameter, or a reference standard, andwherein the LDS analyzer utilizes the inputs to direct operation of theLDS device and to produce the results.
 23. The system as recited inclaim 16, further comprising: a results transmitter, capable ofcommunicating the results to a second system, wherein the second systemis one or more of a well site controller, a well site operation plansystem, a user, a well operator, a downhole tool controller, a datacenter, a computing system, or a cloud environment.
 24. The system asrecited in claim 16, further comprising: a physical-chemical separationdevice, capable of producing second results utilized by the LDS analyzerusing the extracted material, wherein the physical-chemical separationdevice is located proximate the LDS device and is one or more of a gaschromatography (GC) system, a GC combustion system, a liquidchromatography (LC) system, or a LC combustion system.
 25. A computerprogram product having a series of operating instructions stored on anon-transitory computer-readable medium that directs a data processingapparatus when executed thereby to perform operations to analyzeextracted material, the operations comprising: directing a collecting ofextracted material from a location in a subterranean formation, whereinthe location is proximate a position of hydrocarbon operations within aborehole; instructing a preparing of the extracted material, whereinextraneous material is removed; initiating a putting of the extractedmaterial into a laser dispersion spectroscopy (LDS) device; executing aLDS process utilizing the extracted material; generating results from ananalysis of the LDS process; and communicating the results to one ormore other systems, wherein the LDS process utilizes at least one of agas phase analysis, a liquid phase analysis, or an isotropic analysis,and the extracted material is within pores of downhole materialretrieved from the location.